This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
Environmentally conscious and efficient recovery of oil and gas from hydrocarbon reservoirs is a multidimensional problem that has become one of the world's toughest energy challenges. Injection of various gasses into such reservoirs is now utilized for sequestration, pressure maintenance, or enhanced oil recovery operations. In recent years, injection compressor technology has advanced to the point that development plans for some oil and gas fields incorporate them to inject acid or sour gas in underground formations for sequestration or enhanced oil recovery (EOR) operations. The compressor shafts are typically sealed using dry gas seals (DGS) which utilize the principle of sealing between a stationary face against a rotating face by using a gas fluid film. This “seal gas” provides the lubrication and cooling properties needed by the seal for long and reliable operation. Seal gas should be free of particulates, liquids, and heavy components that condense out of the seal gas when expanded across the seal faces.
Typically, dry seal compressors pressurize injection gas streams (e.g. acid or sour gas streams) to pressures in excess of about 4,000 pounds per square inch absolute (psia) with stream flow rates in excess of 100 million standard cubic feet per day (SCFD). To operate without failure, the seals in the compressors should be lubricated with a gas stream that will not condense a liquid phase as its pressure drops when it expands across the seal faces. The seal gas pressure is greater than the compressor suction pressure, but less than the compressor discharge pressure.
One strategy for producing a non-condensing seal gas is to compress a purified low pressure (e.g. less than about 800 psia) methane or nitrogen stream in a reciprocating compressor. Reciprocating compressors are lubricated with cylinder oil that has some miscibility with the gas, especially at high (e.g. greater than about 2,000 psia) pressures. After compression, the gas stream contains oil in the form of either vapor or entrained droplets. The vapor generally can not be filtered out and at high pressures filtration of entrained droplets is typically inefficient. Thus the oil in the high pressure methane stream will have a liquid phase that is either entrained or “drops out” of the gas when the pressure is dropped through the seals or at pressure regulators that control the pressure to the seals. This cylinder oil “carry-over” into the seal gas is expected to damage and cause premature failure of standard dry seal compressors, resulting in significant down-time and lost production.
In some situations, such as high pressure sour gas service, the seal gas has been obtained from a utility source such as a fuel gas system. Fuel gas is predominantly composed of methane, but can contain some amounts of heavier hydrocarbons, CO2, N2 and small quantities of H2S. A typical source of fuel gas for compressor applications is a slip stream taken from the process gas being fed to the dry seal compressor. At low pressures (e.g. similar to the suction pressure of the dry seal compressor), many different technologies such as absorption, gas/liquid phase separation, and glycol dehydration can be used to condition a slip stream for use as fuel gas.
Purifying a slip stream taken from the high pressure discharge of the dry seal compressor is technically challenging. The fuel gas or gas from-another utility gas source is then compressed and used as seal gas. Such gas is used to avoid the liquid contamination or liquid drop out encountered by using the process gas. This requires additional process and separation units to generate the fuel gas and a separate seal gas booster compressor (e.g. a reciprocating compressor), which can itself be a source of oil and particulate contamination. A reciprocating compressor is usually used for this service due to the high compression ratios and low flows. Reciprocating compressors of this type are typically lubricated with cylinder oil that has some miscibility with the gas, especially at high pressures. Thus, it can not be filtered out at high pressure but condenses or “drops out” of the gas when the pressure is dropped through the seals or at pressure regulators that control the pressure to the seals. This cylinder oil “carry-over” into the seal gas may damage and cause premature failure of standard DGS's.
U.S. Pat. No. 5,976,221 discloses a method of oil removal from vapor utilizing polymeric adsorption. Such a method only removes about 99.9% of the oil. Such results are good, but even a small amount of oil can damage a DGS and cause significant downtime.
U.S. Pat. No. 4,325,565 discloses a method of oil removal including heating the gas stream to fully vaporize the oil in the stream before adsorbing the oil. Although this technique appeared to be effective, it requires additional energy use and processing equipment to achieve beneficial results.
Hence, an improved method of removing oil from process gas for use in dry seals is needed.